Integrated hydrotreating, solvent deasphalting and steam pyrolysis process for direct processing of a crude oil

ABSTRACT

A process is provided that is directed to a steam pyrolysis zone integrated with a hydrotreating zone and a solvent deasphalting zone to permit direct processing of crude oil feedstocks to produce petrochemicals including olefins and aromatics. The integrated hydrotreating, solvent deasphalting and steam pyrolysis process comprises charging the crude oil to a hydroprocessing zone operating under conditions effective to produce a hydroprocessed effluent reduced having a reduced content of contaminants, an increased paraffinicity, reduced Bureau of Mines Correlation Index, and an increased American Petroleum Institute gravity; charging the hydroprocessed effluent to a solvent deasphalting zone with an effective amount of solvent to produce a deasphalted and demetalized oil stream and a bottom asphalt phase; thermally cracking the deasphalted and demetalized oil stream in the presence of steam to produce a mixed product stream; separating the mixed product stream; purifying hydrogen recovered from the mixed product stream and recycling it to the hydroprocessing zone; recovering olefins and aromatics from the separated mixed product stream; and recovering pyrolysis fuel oil from the separated mixed product stream.

RELATED APPLICATIONS

This application claims the benefit of U.S. Provisional PatentApplication No. 61/591,776 filed Jan. 27, 2012, the disclosure of whichis hereby incorporated by reference in its entirety.

BACKGROUND OF THE INVENTION

1. Field of the Invention

The present invention relates to an integrated hydrotreating, solventdeasphalting and steam pyrolysis process for direct processing of acrude oil to produce petrochemicals such as olefins and aromatics.

2. Description of Related Art

The lower olefins (i.e., ethylene, propylene, butylene and butadiene)and aromatics (i.e., benzene, toluene and xylene) are basicintermediates which are widely used in the petrochemical and chemicalindustries. Thermal cracking, or steam pyrolysis, is a major type ofprocess for forming these materials, typically in the presence of steam,and in the absence of oxygen. Feedstocks for steam pyrolysis can includepetroleum gases and distillates such as naphtha, kerosene and gas oil.The availability of these feedstocks is usually limited and requirescostly and energy-intensive process steps in a crude oil refinery.

Studies have been conducted using heavy hydrocarbons as a feedstock forsteam pyrolysis reactors. A major drawback in conventional heavyhydrocarbon pyrolysis operations is coke formation. For example, a steamcracking process for heavy liquid hydrocarbons is disclosed in U.S. Pat.No. 4,217,204 in which a mist of molten salt is introduced into a steamcracking reaction zone in an effort to minimize coke formation. In oneexample using Arabian light crude oil having a Conradson carbon residueof 3.1% by weight, the cracking apparatus was able to continue operatingfor 624 hours in the presence of molten salt. In a comparative examplewithout the addition of molten salt, the steam cracking reactor becameclogged and inoperable after just 5 hours because of the formation ofcoke in the reactor.

In addition, the yields and distributions of olefins and aromatics usingheavy hydrocarbons as a feedstock for a steam pyrolysis reactor aredifferent than those using light hydrocarbon feedstocks. Heavyhydrocarbons have a higher content of aromatics than light hydrocarbons,as indicated by a higher Bureau of Mines Correlation Index (BMCI). BMCIis a measurement of aromaticity of a feedstock and is calculated asfollows:

BMCI=87552/VAPB+473.5*(sp. gr.)−456.8  (1)

-   -   where:    -   VAPB=Volume Average Boiling Point in degrees Rankine and    -   sp. gr.=specific gravity of the feedstock.

As the BMCI decreases, ethylene yields are expected to increase.Therefore, highly paraffinic or low aromatic feeds are usually preferredfor steam pyrolysis to obtain higher yields of desired olefins and toavoid higher undesirable products and coke formation in the reactor coilsection.

The absolute coke formation rates in a steam cracker have been reportedby Cai et al., “Coke Formation in Steam Crackers for EthyleneProduction,” Chem. Eng. & Proc., vol. 41, (2002), 199-214. In general,the absolute coke formation rates are in the ascending order ofolefins>aromatics>paraffins, wherein olefins represent heavy olefins

To be able to respond to the growing demand of these petrochemicals,other type of feeds which can be made available in larger quantities,such as raw crude oil, are attractive to producers. Using crude oilfeeds will minimize or eliminate the likelihood of the refinery being abottleneck in the production of these petrochemicals.

While the steam pyrolysis process is well developed and suitable for itsintended purposes, the choice of feedstocks has been very limited.

SUMMARY OF THE INVENTION

The system and process herein provides a steam pyrolysis zone integratedwith hydrotreating zone and a solvent deasphalting zone to permit directprocessing of crude oil feedstocks to produce petrochemicals includingolefins and aromatics.

The integrated hydrotreating, solvent deasphalting and steam pyrolysisprocess comprises charging the crude oil to a hydroprocessing zoneoperating under conditions effective to produce a hydroprocessedeffluent reduced having a reduced content of contaminants, an increasedparaffinicity, reduced Bureau of Mines Correlation Index, and anincreased American Petroleum Institute gravity; charging thehydroprocessed effluent to a solvent deasphalting zone with an effectiveamount of solvent to produce a deasphalted and demetalized oil streamand a bottom asphalt phase; thermally cracking the deasphalted anddemetalized oil stream in the presence of steam to produce a mixedproduct stream; separating the mixed product stream; purifying hydrogenrecovered from the mixed product stream and recycling it to thehydroprocessing zone; recovering olefins and aromatics from theseparated mixed product stream; and recovering pyrolysis fuel oil fromthe separated mixed product stream.

As used herein, the term “crude oil” is to be understood to includewhole crude oil from conventional sources, crude oil that has undergonesome pre-treatment. The term crude oil will also be understood toinclude that which has been subjected to water-oil separation; and/orgas-oil separation; and/or desalting; and/or stabilization.

Other aspects, embodiments, and advantages of the process of the presentinvention are discussed in detail below. Moreover, it is to beunderstood that both the foregoing information and the followingdetailed description are merely illustrative examples of various aspectsand embodiments, and are intended to provide an overview or frameworkfor understanding the nature and character of the claimed features andembodiments. The accompanying drawings are illustrative and are providedto further the understanding of the various aspects and embodiments ofthe process of the invention.

BRIEF DESCRIPTION OF THE DRAWINGS

The invention will be described in further detail below and withreference to the attached drawings where:

FIG. 1 is a process flow diagram of an embodiment of an integratedprocess described herein; and

FIGS. 2A-2C are schematic illustrations in perspective, top and sideviews of a vapor-liquid separation device used in certain embodiments ofa steam pyrolysis unit in the integrated process described herein.

DETAILED DESCRIPTION OF THE INVENTION

A flow diagram including an integrated hydrotreating, solventdeasphalting and steam pyrolysis process and system is shown in FIG. 1.The system includes a selective catalytic hydroprocessing zone, asolvent deasphalting zone, a steam pyrolysis zone and a productseparation zone.

The selective hydroprocessing zone includes a reactor zone 4 includingan inlet for receiving a combined stream 3 including a crude oil feedstream 1 and hydrogen 2 recycled from the steam pyrolysis productstream, and make-up hydrogen if necessary (not shown). Reactor zone 4also includes an outlet for discharging a hydroprocessed effluent 5.

Reactor effluents 5 from the hydroprocessing reactor(s) are cooled in aheat exchanger (not shown) and sent to a high pressure separator 6. Theseparator tops 7 are cleaned in an amine unit 12 and a resultinghydrogen rich gas stream 13 is passed to a recycling compressor 14 to beused as a recycle gas 15 in the hydroprocessing reactor. A bottomsstream 8 from the high pressure separator 6, which is in a substantiallyliquid phase, is cooled and introduced to a low pressure cold separator9 in which it is separated into a gas stream and a liquid stream 10.Gases from low pressure cold separator includes hydrogen, H₂S, NH₃ andany light hydrocarbons such as C₁-C₄ hydrocarbons. Typically these gasesare sent for further processing such as flare processing or fuel gasprocessing. According to certain embodiments herein, hydrogen isrecovered by combining stream gas stream 11, which includes hydrogen,H₂S, NH₃ and any light hydrocarbons such as C₁-C₄ hydrocarbons, withsteam cracker products 44. All or a portion of liquid stream 10 servesas the feed to the solvent deasphalting zone

Solvent deasphalting zone generally includes a primary settler 19, asecondary settler 22, a deasphalted/demetalized oil (DA/DMO) separationzone 25, and a separator zone 27. Primary settler 19 includes an inletfor receiving hydroprocessed effluent 10and a solvent, which can befresh solvent 16, recycle solvent 17, recycle solvent 28, or acombination of these solvent sources. Primary settler 19 also includesan outlet for discharging a primary DA/DMO phase 20 and several pipeoutlets for discharging a primary asphalt phase 21. Secondary settler 22includes two tee-type distributors located at both ends for receivingthe primary DA/DMO phase 20, an outlet for discharging a secondaryDA/DMO phase 24, and an outlet for discharging a secondary asphalt phase23. DA/DMO separation zone 25 includes an inlet for receiving secondaryDA/DMO phase 24, an outlet for discharging a solvent stream 17 and anoutlet for discharging a solvent-free DA/DMO stream 26, which serves asthe feed for the steam pyrolysis zone 30. Separator vessel 27 includesan inlet for receiving primary asphalt phase 21, an outlet fordischarging a solvent stream 28, and an outlet for discharging a bottomasphalt phase 29, which can be blended with pyrolysis fuel oil 71 fromthe product separation zone 70.

Steam pyrolysis zone 30 generally comprises a convection section 32 anda pyrolysis section 34 that can operate based on steam pyrolysis unitoperations known in the art, i.e., charging the thermal cracking feed tothe convection section in presence of steam. In addition, in certainoptional embodiments as described herein (as indicated with dashed linesin FIG. 1), a vapor-liquid separation section 36 is included betweensections 32 and 34. Vapor-liquid separation section 36, through whichthe heated steam cracking feed from convection section 32 passes, can bea separation device based on physical or mechanical separation of vaporsand liquids.

In one embodiment, a vapor-liquid separation device is illustrated by,and with reference to FIGS. 2A-2C. A similar arrangement of avapor-liquid separation device is also described in U.S. PatentPublication Number 2011/0247500 which is incorporated by reference inits entirety herein. In this device vapor and liquid flow through in acyclonic geometry whereby the device operates isothermally and at verylow residence time. In general vapor is swirled in a circular pattern tocreate forces where heavier droplets and liquid are captured andchanneled through to a liquid outlet as low-sulfur fuel oil 38, forinstance, which is added to a pyrolysis fuel oil blend, and vapor ischanneled through as the charge 37 to the pyrolysis section 34. Thevaporization temperature and fluid velocity are varied to adjust theapproximate temperature cutoff point, for instance in certainembodiments compatible with the residue fuel oil blend, e.g., about 540°C.

A quenching zone 40 includes an inlet in fluid communication with theoutlet of steam pyrolysis zone 30, an inlet for admitting a quenchingsolution 42, an outlet for discharging an intermediate quenched mixedproduct stream 44 and an outlet for discharging quenching solution 46.

In general, an intermediate quenched mixed product stream 44 isconverted into intermediate product stream 65 and hydrogen 62, which ispurified in the present process and used as recycle hydrogen stream 2 inthe hydroprocessing reaction zone 4. Intermediate product stream 65 isgenerally fractioned into end-products and residue in separation zone70, which can one or multiple separation units such as pluralfractionation towers including de-ethanizer, de-propanizer andde-butanizer towers, for example as is known to one of ordinary skill inthe art. For example, suitable apparatus are described in “Ethylene,”Ullmann's Encyclopedia of Industrial Chemistry, Volume 12, Pages531-581, in particular FIG. 24, FIG. 25 and FIG. 26, which isincorporated herein by reference.

In general product separation zone 70 includes an inlet in fluidcommunication with the product stream 65 and plural product outlets73-78, including an outlet 78 for discharging methane, an outlet 77 fordischarging ethylene, an outlet 76 for discharging propylene, an outlet75 for discharging butadiene, an outlet 74 for discharging mixedbutylenes, and an outlet 73 for discharging pyrolysis gasoline.Additionally an outlet is provided for discharging pyrolysis fuel oil71. Optionally, one or both of the bottom asphalt phase 29 from solventdeasphalting zone separator vessel 27 and the fuel oil portion 38 fromvapor-liquid separation section 36 are combined with pyrolysis fuel oil71 and the mixed stream can be withdrawn as a pyrolysis fuel oil blend72, e.g., a low sulfur fuel oil blend to be further processed in anoff-site refinery. Note that while six product outlets are shown, feweror more can be provided depending, for instance, on the arrangement ofseparation units employed and the yield and distribution requirements.

In an embodiment of a process employing the arrangement shown in FIG. 1,a crude oil feedstock 1 is mixed with an effective amount of hydrogen 2and 15 (and if necessary a source of make-up hydrogen) to form acombined stream 3. The admixture 3 is charged to the hydroprocessingreaction zone 4 at a temperature in the range of from 300° C. to 450° C.In certain embodiments, hydroprocessing reaction zone 4 includes one ormore unit operations as described in commonly owned United States PatentPublication Number 2011/0083996 and in PCT Patent ApplicationPublication Numbers WO2010/009077, WO2010/009082, WO2010/009089 andWO2009/073436, all of which are incorporated by reference herein intheir entireties. For instance, a hydroprocessing zone can include oneor more beds containing an effective amount of hydrodemetallizationcatalyst, and one or more beds containing an effective amount ofhydroprocessing catalyst having hydrodearomatization,hydrodenitrogenation, hydrodesulfurization and/or hydrocrackingfunctions. In additional embodiments hydroprocessing reaction zone 4includes more than two catalyst beds. In further embodimentshydroprocessing reaction zone 4 includes plural reaction vessels eachcontaining one or more catalyst beds, e.g., of different function.

Hydroprocessing zone 4 operates under parameters effective tohydrodemetallize, hydrodearomatize, hydrodenitrogenate, hydrodesulfurizeand/or hydrocrack the crude oil feedstock. In certain embodiments,hydroprocessing is carried out using the following conditions: operatingtemperature in the range of from 300° C. to 450° C.; operating pressurein the range of from 30 bars to 180 bars; and a liquid hour spacevelocity in the range of from 0.1 h⁻¹ to 10 h⁻¹. Notably, using crudeoil as a feedstock in the hydroprocessing zone 200 advantages aredemonstrated, for instance, as compared to the same hydroprocessing unitoperation employed for atmospheric residue. For instance, at a start orrun temperature in the range of 370° C. to 375° C. the deactivation rateis around 1° C./month. In contrast, if residue were to be processed, thedeactivation rate would be closer to about 3° C./month to 4° C./month.The treatment of atmospheric residue typically employs pressure ofaround 200 bars whereas the present process in which crude oil istreated can operate at a pressure as low as 100 bars. Additionally toachieve the high level of saturation required for the increase in thehydrogen content of the feed, this process can be operated at a highthroughput when compared to atmospheric residue. The LHSV can be as highas 0.5 while that for atmospheric residue is typically 0.25. Anunexpected finding is that the deactivation rate when processing crudeoil is going in the inverse direction from that which is usuallyobserved. Deactivation at low throughput (0.25 hr⁻¹) is 4.2° C./monthand deactivation at higher throughput (0.5 hr⁻¹) is 2.0° C./month. Withevery feed which is considered in the industry, the opposite isobserved. This can be attributed to the washing effect of the catalyst.

Reactor effluents 5 from the hydroprocessing zone 4 are cooled in anexchanger (not shown) and sent to a high pressure cold or hot separator6. Separator tops 7 are cleaned in an amine unit 12 and the resultinghydrogen rich gas stream 13 is passed to a recycling compressor 14 to beused as a recycle gas 15 in the hydroprocessing reaction zone 4.Separator bottoms 8 from the high pressure separator 6, which are in asubstantially liquid phase, are cooled and then introduced to a lowpressure cold separator 9. Remaining gases, stream 11, includinghydrogen, H₂S, NH₃ and any light hydrocarbons, which can include C₁-C₄hydrocarbons, can be conventionally purged from the low pressure coldseparator and sent for further processing, such as flare processing orfuel gas processing. In certain embodiments of the present process,hydrogen is recovered by combining stream 11 (as indicated by dashedlines) with the cracking gas, stream 44, from the steam crackerproducts. The bottoms 10 from the low pressure separator 9 areoptionally sent to separation zone 20 or passed directly to steampyrolysis zone 30.

The hydroprocessed effluent 10 contains a reduced content ofcontaminants (i.e., metals, sulfur and nitrogen), an increasedparaffinicity, reduced BMCI, and an increased American PetroleumInstitute (API) gravity.

The hydrotreated effluent 10 is admixed with solvent from one or moresources 16, 17 and 28. The resulting mixture 18 is then transferred tothe primary settler 19. By mixing and settling, two phases are formed inthe primary settler 19: a primary DA/DMO phase 20 and a primary asphaltphase 21. The temperature of the primary settler 19 is sufficiently lowto recover all DA/DMO from the feedstock. For instance, for a systemusing n-butane a suitable temperature range is about 60° C. to 150° C.and a suitable pressure range is such that it is higher than the vaporpressure of n-butane at the operating temperature e.g. about 15 to 25bars to maintain the solvent in liquid phase. In a system usingn-pentane a suitable temperature range is about 60° C. to about 180° C.and again a suitable pressure range is such that it is higher than thevapor pressure of n-pentane at the operating temperature e.g. about 10to 25 bars to maintain the solvent in liquid phase. The temperature inthe second settler is usually higher than the one in the first settler.

The primary DA/DMO phase 20 including a majority of solvent and DA/DMOwith a minor amount of asphalt is discharged via the outlet located atthe top of the primary settler 19 and collector pipes (not shown). Theprimary asphalt phase 21, which contains 40-50% by volume of solvent, isdischarged via several pipe outlets located at the bottom of the primarysettler 19.

The primary DA/DMO phase 20 enters into the two tee-type distributors atboth ends of the secondary settler 22 which serves as the final stagefor the extraction. A secondary asphalt phase 23 containing a smallamount of solvent and DA/DMO is discharged from the secondary settler 22and recycled back to the primary settler 19 to recover DA/DMO. Asecondary DA/DMO phase 24 is obtained and passed to the DA/DMOseparation zone 25 to obtain a solvent stream 17 and a solvent-freeDA/DMO stream 26. Greater than 90 wt % of the solvent charged to thesettlers enters the DA/DMO separation zone 25, which is dimensioned topermit a rapid and efficient flash separation of solvent from theDA/DMO. The primary asphalt phase 21 is conveyed to the separator vessel27 for flash separation of a solvent stream 28 and a bottom asphaltphase 29. Solvent streams 17 and 28 can be used as solvent for theprimary settler 19, therefore minimizing the fresh solvent 16requirement.

The solvents used in solvent deasphalting zone include pure liquidhydrocarbons such as propane, butanes and pentanes, as well as theirmixtures. The selection of solvents depends on the requirement of DAO,as well as the quality and quantity of the final products. The operatingconditions for the solvent deasphalting zone include a temperature at orbelow critical point of the solvent; a solvent-to-oil ratio in the rangeof from 2:1 to 50:1; and a pressure in a range effective to maintain thesolvent/feed mixture in the settlers is in the liquid state.

The essentially solvent-free DA/DMO stream 26 is optionally steamstripped (not shown) to remove solvent and conveyed to the convectionsection 32 in the presence of a predetermined amount of steam, e.g.,admitted via a steam inlet (not shown). In the convection section 32 themixture is heated to a predetermined temperature, e.g., using one ormore waste heat streams or other suitable heating arrangement. Theheated mixture of the pyrolysis feedstream and additional steam ispassed to the pyrolysis section 34 to produce a mixed product stream 39.In certain embodiments the heated mixture of from section 32 is passedthrough a vapor-liquid separation section 36 in which a portion 38 isrejected as a low sulfur fuel oil component suitable for blending withpyrolysis fuel oil 71.

The steam pyrolysis zone 30 operates under parameters effective to crackthe DA/DMO stream into desired products including ethylene, propylene,butadiene, mixed butenes and pyrolysis gasoline. In certain embodiments,steam cracking is carried out using the following conditions: atemperature in the range of from 400° C. to 900° C. in the convectionsection and in the pyrolysis section; a steam-to-hydrocarbon ratio inthe convection zone in the range of from 0.3:1 to 2:1; and a residencetime in the convection section and in the pyrolysis section in the rangeof from 0.05 seconds to 2 seconds.

In certain embodiments, the vapor-liquid separation section 36 includesone or a plurality of vapor liquid separation devices 80 as shown inFIGS. 2A-2C. The vapor liquid separation device 80 is economical tooperate and maintenance free since it does not require power or chemicalsupplies. In general, device 80 comprises three ports including an inletport for receiving a vapor-liquid mixture, a vapor outlet port and aliquid outlet port for discharging and the collection of the separatedvapor and liquid, respectively. Device 80 operates based on acombination of phenomena including conversion of the linear velocity ofthe incoming mixture into a rotational velocity by the global flowpre-rotational section, a controlled centrifugal effect to pre-separatethe vapor from liquid (residue), and a cyclonic effect to promoteseparation of vapor from the liquid (residue). To attain these effects,device 80 includes a pre-rotational section 88, a controlled cyclonicvertical section 90 and a liquid collector/settling section 92.

As shown in FIG. 2B, the pre-rotational section 88 includes a controlledpre-rotational element between cross-section (S1) and cross-section(S2), and a connection element to the controlled cyclonic verticalsection 90 and located between cross-section (S2) and cross-section(S3). The vapor liquid mixture coming from inlet 82 having a diameter(D1) enters the apparatus tangentially at the cross-section (S1). Thearea of the entry section (S1) for the incoming flow is at least 10% ofthe area of the inlet 82 according to the following equation:

$\begin{matrix}\frac{\pi*\left( \left( {D\; 1} \right) \right)^{2}}{4} & (1)\end{matrix}$

The pre-rotational element 88 defines a curvilinear flow path, and ischaracterized by constant, decreasing or increasing cross-section fromthe inlet cross-section S1 to the outlet cross-section S2. The ratiobetween outlet cross-section from controlled pre-rotational element (S2)and the inlet cross-section (S) is in certain embodiments in the rangeof 0.7≦S2/S1≦1.4.

The rotational velocity of the mixture is dependent on the radius ofcurvature (R) of the center-line of the pre-rotational element 38 wherethe center-line is defined as a curvilinear line joining all the centerpoints of successive cross-sectional surfaces of the pre-rotationalelement 88. In certain embodiments the radius of curvature (R) is in therange of 2≦R1/D1≦6 with opening angle in the range of 150°<αR1<250°.

The cross-sectional shape at the inlet section S1, although depicted asgenerally square, can be a rectangle, a rounded rectangle, a circle, anoval, or other rectilinear, curvilinear or a combination of theaforementioned shapes. In certain embodiments, the shape of thecross-section along the curvilinear path of the pre-rotational element38 through which the fluid passes progressively changes, for instance,from a generally square shape to a rectangular shape. The progressivelychanging cross-section of element 88 into a rectangular shapeadvantageously maximizes the opening area, thus allowing the gas toseparate from the liquid mixture at an early stage and to attain auniform velocity profile and minimize shear stresses in the fluid flow.

The fluid flow from the controlled pre-rotational element 88 fromcross-section (S2) passes section (S3) through the connection element tothe controlled cyclonic vertical section 90. The connection elementincludes an opening region that is open and connected to, or integralwith, an inlet in the controlled cyclonic vertical section 90. The fluidflow enters the controlled cyclonic vertical section 90 at a highrotational velocity to generate the cyclonic effect. The ratio betweenconnection element outlet cross-section (S3) and inlet cross-section(S2) in certain embodiments is in the range of 2≦S3/S1≦5.

The mixture at a high rotational velocity enters the cyclonic verticalsection 90. Kinetic energy is decreased and the vapor separates from theliquid under the cyclonic effect. Cyclones form in the upper level 90 aand the lower level 90 b of the cyclonic vertical section 90. In theupper level 90 a, the mixture is characterized by a high concentrationof vapor, while in the lower level 90 b the mixture is characterized bya high concentration of liquid.

In certain embodiments, the internal diameter D2 of the cyclonicvertical section 90 is within the range of 2≦D2/D1≦5 and can be constantalong its height, the length (LU) of the upper portion 90 a is in therange of 1.2≦LU/D2≦3, and the length (LL) of the lower portion 90 b isin the range of 2≦LL/D2≦5.

The end of the cyclonic vertical section 90 proximate vapor outlet 84 isconnected to a partially open release riser and connected to thepyrolysis section of the steam pyrolysis unit. The diameter (DV) of thepartially open release is in certain embodiments in the range of0.05≦DV/D2≦0.4.

Accordingly, in certain embodiments, and depending on the properties ofthe incoming mixture, a large volume fraction of the vapor therein exitsdevice 80 from the outlet 84 through the partially open release pipewith a diameter DV. The liquid phase (e.g., residue) with a low ornon-existent vapor concentration exits through a bottom portion of thecyclonic vertical section 90 having a cross-sectional area S4, and iscollected in the liquid collector and settling pipe 92.

The connection area between the cyclonic vertical section 90 and theliquid collector and settling pipe 92 has an angle in certain embodimentof 90°. In certain embodiments the internal diameter of the liquidcollector and settling pipe 92 is in the range of 2≦D3/D1≦4 and isconstant across the pipe length, and the length (LH) of the liquidcollector and settling pipe 92 is in the range of 1.2≦LH/D3≦5. Theliquid with low vapor volume fraction is removed from the apparatusthrough pipe 86 having a diameter of DL, which in certain embodiments isin the range of 0.05≦DL/D3≦0.4 and located at the bottom or proximatethe bottom of the settling pipe

While the various members are described separately and with separateportions, it will be understood by one of ordinary skill in the art thatapparatus 30 can be formed as a monolithic structure, e.g., it can becast or molded, or it can be assembled from separate parts, e.g., bywelding or otherwise attaching separate components together which may ormay not correspond precisely to the members and portions describedherein.

It will be appreciated that although various dimensions are set forth asdiameters, these values can also be equivalent effective diameters inembodiments in which the components parts are not cylindrical.

Mixed product stream 39 is passed to the inlet of quenching zone 40 witha quenching solution 42 (e.g., water and/or pyrolysis fuel oil)introduced via a separate inlet to produce a quenched mixed productstream 44 having a reduced temperature, e.g., of about 300° C., andspent quenching solution 46 is discharged.

The gas mixture effluent 39 from the cracker is typically a mixture ofhydrogen, methane, hydrocarbons, carbon dioxide and hydrogen sulfide.After cooling with water or oil quench, mixture 44 is compressed in amulti-stage compressor zone 51, typically in 4-6 stages to produce acompressed gas mixture 52. The compressed gas mixture 52 is treated in acaustic treatment unit 53 to produce a gas mixture 54 depleted ofhydrogen sulfide and carbon dioxide. The gas mixture 54 is furthercompressed in a compressor zone 55, and the resulting cracked gas 56typically undergoes a cryogenic treatment in unit 57 to be dehydrated,and is further dried by use of molecular sieves.

The cold cracked gas stream 58 from unit 57 is passed to a de-methanizertower 59, from which an overhead stream 60 is produced containinghydrogen and methane from the cracked gas stream. The bottoms stream 65from de-methanizer tower 59 is then sent for further processing inproduct separation zone 70, comprising fractionation towers includingde-ethanizer, de-propanizer and de-butanizer towers. Processconfigurations with a different sequence of de-methanizer, de-ethanizer,de-propanizer and de-butanizer can also be employed.

According to the processes herein, after separation from methane at thede-methanizer tower 59 and hydrogen recovery in unit 61, hydrogen 62having a purity of typically 80-95 vol % is obtained. Recovery methodsin unit 61 include cryogenic recovery (e.g., at a temperature of about−157° C.). Hydrogen stream 62 is then passed to a hydrogen purificationunit 64, such as a pressure swing adsorption (PSA) unit to obtain ahydrogen stream 2 having a purity of 99.9%+, or a membrane separationunits to obtain a hydrogen stream 2 with a purity of about 95%. Thepurified hydrogen stream 2 is then recycled back to serve as a majorportion of the requisite hydrogen for the hydroprocessing zone. Inaddition, a minor proportion can be utilized for the hydrogenationreactions of acetylene, methylacetylene and propadienes (not shown). Inaddition, according to the processes herein, methane stream 63 canoptionally be recycled to the steam cracker to be used as fuel forburners and/or heaters.

The bottoms stream 65 from de-methanizer tower 59 is conveyed to theinlet of product separation zone 70 to be separated into methane,ethylene, propylene, butadiene, mixed butylenes and pyrolysis gasolinevia outlets 78, 77, 76, 75, 74 and 73, respectively. Pyrolysis gasolinegenerally includes C5-C9 hydrocarbons, and benzene, toluene and xylenescan be extracted from this cut. Optionally, one or both of the bottomasphalt phase 29 and the unvaporized heavy liquid fraction 38 from thevapor-liquid separation section 36 are combined with pyrolysis fuel oil71 (e.g., materials boiling at a temperature higher than the boilingpoint of the lowest boiling C10 compound, known as a “C10+” stream) fromseparation zone 70, and the mixed stream is withdrawn as a pyrolysisfuel oil blend 72, e.g., to be further processed in an off-site refinery(not shown). In certain embodiments, the bottom asphalt phase 29 can besent to an asphalt stripper (not shown) where any remaining solvent isstripped-off, e.g., by steam.

In certain embodiments, selective hydroprocessing or hydrotreatingprocesses can increase the paraffin content (or decrease the BMCI) of afeedstock by saturation followed by mild hydrocracking of aromatics,especially polyaromatics. When hydrotreating a crude oil, contaminantssuch as metals, sulfur and nitrogen can be removed by passing thefeedstock through a series of layered catalysts that perform thecatalytic functions of demetallization, desulfurization and/ordenitrogenation.

In one embodiment, the sequence of catalysts to performhydrodemetallization (HDM) and hydrodesulfurization (HDS) is as follows:

-   -   a. A hydrodemetallization catalyst. The catalyst in the HDM        section are generally based on a gamma alumina support, with a        surface area of about 140-240 m²/g. This catalyst is best        described as having a very high pore volume, e.g., in excess of        1 cm³/g. The pore size itself is typically predominantly        macroporous. This is required to provide a large capacity for        the uptake of metals on the catalysts surface and optionally        dopants. Typically the active metals on the catalyst surface are        sulfides of Nickel and Molybdenum in the ratio Ni/Ni+Mo<0.15.        The concentration of Nickel is lower on the HDM catalyst than        other catalysts as some Nickel and Vanadium is anticipated to be        deposited from the feedstock itself during the removal, acting        as catalyst. The dopant used can be one or more of phosphorus        (see, e.g., United States Patent Publication Number US        2005/0211603 which is incorporated by reference herein), boron,        silicon and halogens. The catalyst can be in the form of alumina        extrudates or alumina beads. In certain embodiments alumina        beads are used to facilitate un-loading of the catalyst HDM beds        in the reactor as the metals uptake will range between from 30        to 100% at the top of the bed.    -   b. An intermediate catalyst can also be used to perform a        transition between the HDM and HDS function. It has intermediate        metals loadings and pore size distribution. The catalyst in the        HDM/HDS reactor is essentially alumina based support in the form        of extrudates, optionally at least one catalytic metal from        group VI (e.g., molybdenum and/or tungsten), and/or at least one        catalytic metals from group VIII (e.g., nickel and/or cobalt).        The catalyst also contains optionally at least one dopant        selected from boron, phosphorous, halogens and silicon. Physical        properties include a surface area of about 140-200 m²/g, a pore        volume of at least 0.6 cm³/g and pores which are mesoporous and        in the range of 12 to 50 nm.    -   c. The catalyst in the HDS section can include those having        gamma alumina based support materials, with typical surface area        towards the higher end of the HDM range, e.g. about ranging from        180-240 m²/g. This required higher surface for HDS results in        relatively smaller pore volume, e.g., lower than 1 cm³/g. The        catalyst contains at least one element from group VI, such as        molybdenum and at least one element from group VIII, such as        nickel. The catalyst also comprises at least one dopant selected        from boron, phosphorous, silicon and halogens. In certain        embodiments cobalt is used to provide relatively higher levels        of desulfurization. The metals loading for the active phase is        higher as the required activity is higher, such that the molar        ratio of Ni/Ni+Mo is in the range of from 0.1 to 0.3 and the        (Co+Ni)/Mo molar ratio is in the range of from 0.25 to 0.85.    -   d. A final catalyst (which could optionally replace the second        and third catalyst) is designed to perform hydrogenation of the        feedstock (rather than a primary function of        hydrodesulfurization), for instance as described in Appl. Catal.        A General, 204 (2000) 251. The catalyst will be also promoted by        Ni and the support will be wide pore gamma alumina. Physical        properties include a surface area towards the higher end of the        HDM range, e.g., 180-240 m²/g. This required higher surface for        HDS results in relatively smaller pore volume, e.g., lower than        1 cm³/g.

Solvent deasphalting is a unique separation process in which residue isseparated by molecular weight (density), instead of by boiling point, asin the vacuum distillation process. The solvent deasphalting processthus produces a low-contaminant deasphalted oil (DAO) rich in paraffinictype molecules, consequently decreases the BMCI as compared to theinitial feedstock or the hydroprocessed feedstock.

Solvent deasphalting is usually carried out with paraffin streams havingcarbon number ranging from 3-7, in certain embodiments ranging from 4-5,and below the critical conditions of the solvent. Table 1 lists theproperties of commonly used solvents in solvent deasphalting.

TABLE 1 Properties Of Commonly Used Solvents In Solvent DeasphaltingBoiling Critical Critical MW Point Specific Temperature Pressure NameFormula g/g-mol ° C. Gravity ° C. bar propane C3H8 44.1 −42.1 0.508 96.842.5 n-butane C4H10 58.1 −0.5 0.585 152.1 37.9 i--butane C4H10 58.1−11.7 0.563 135.0 36.5 n-pentane C5H12 72.2 36.1 0.631 196.7 33.8i--pentane C5H12 72.2 27.9 0.625 187.3 33.8

The feed is mixed with a light paraffinic solvent with carbon numbersranging 3-7, where the deasphalted oil is solubilized in the solvent.The insoluble pitch will precipitate out of the mixed solution and isseparated from the DAO phase (solvent-DAO mixture) in the extractor.

Solvent deasphalting is carried-out in liquid phase and therefore thetemperature and pressure are set accordingly. There are two stages forphase separation in solvent deasphalting. In the first separation stage,the temperature is maintained lower than that of the second stage toseparate the bulk of the asphaltenes. The second stage temperature ismaintained to control the deasphalted/demetalized oil (DA/DMO) qualityand quantity. The temperature has big impact on the quality and quantityof DA/DMO. An extraction temperature increase will result in a decreasein deasphalted/demetalized oil yield, which means that the DA/DMO willbe lighter, less viscous, and contain less metals, asphaltenes, sulfur,and nitrogen. A temperature decrease will have the opposite effects. Ingeneral, the DA/DMO yield decreases having lower quality by raisingextraction system temperature and increases having lower quality bylowering extraction system temperature.

The composition of the solvent is an important process variable. Thesolubility of the solvent increases with increasing criticaltemperature, generally according to C3<iC4<nC4<iC5. An increase incritical temperature of the solvent increases the DA/DMO yield. However,it should be noted that the solvent having the higher criticaltemperature has less selectivity resulting in lower DA/DMO quality.

The volumetric ratio of the solvent to the solvent deasphalting unitcharge impacts selectivity and to a lesser degree on the DA/DMO yield.Higher solvent-to-oil ratios result in a higher quality of the DA/DMOfor a fixed DA/DMO yield. Higher solvent-to-oil ratio is desirable dueto better selectivity, but can result in increased operating coststhereby the solvent-to-oil ratio is often limited to a narrow range. Thecomposition of the solvent will also help to establish the requiredsolvent to oil ratios. The required solvent to oil ratio decreases asthe critical solvent temperature increases. The solvent to oil ratio is,therefore, a function of desired selectivity, operation costs andsolvent composition.

The method and system herein provides improvements over known steampyrolysis cracking processes:use of crude oil as a feedstock to producepetrochemicals such as olefins and aromatics;

-   -   the hydrogen content of the feed to the steam pyrolysis zone is        enriched for high yield of olefins;    -   coke precursors are significantly removed from the initial whole        crude oil which allows a decreased coke formation in the radiant        coil; and    -   additional impurities such as metals, sulfur and nitrogen        compounds are also significantly removed from the starting feed        which avoids post treatments of the final products.

In addition, hydrogen produced from the steam cracking zone is recycledto the hydroprocessing zone to minimize the demand for fresh hydrogen.In certain embodiments the integrated systems described herein onlyrequire fresh hydrogen to initiate the operation. Once the reactionreaches the equilibrium, the hydrogen purification system can provideenough high purity hydrogen to maintain the operation of the entiresystem.

The method and system of the present invention have been described aboveand in the attached drawings; however, modifications will be apparent tothose of ordinary skill in the art and the scope of protection for theinvention is to be defined by the claims that follow.

1. An integrated hydrotreating, solvent deasphalting and steam pyrolysisprocess for the direct processing of a crude oil to produce olefinic andaromatic petrochemicals, the process comprising: a. charging the crudeoil to a hydroprocessing zone operating under conditions effective toproduce a hydroprocessed effluent reduced having a reduced content ofcontaminants, an increased paraffinicity, reduced Bureau of MinesCorrelation Index, and an increased American Petroleum Institutegravity; b. charging the hydroprocessed effluent to a solventdeasphalting zone with an effective amount of solvent to produce adeasphalted and demetalized oil stream and a bottom asphalt phase; c.thermally cracking the deasphalted and demetalized oil stream in thepresence of steam to produce a mixed product stream; d. separating thethermally cracked mixed product stream; e. purifying hydrogen recoveredin step (d) and recycling it to step (a); f. recovering olefins andaromatics from the separated mixed product stream; and g. recoveringpyrolysis fuel oil from the separated mixed product stream.
 2. Theintegrated process of claim 1, wherein step (d) comprises compressingthe thermally cracked mixed product stream with plural compressionstages; subjecting the compressed thermally cracked mixed product streamto caustic treatment to produce a thermally cracked mixed product streamwith a reduced content of hydrogen sulfide and carbon dioxide;compressing the thermally cracked mixed product stream with a reducedcontent of hydrogen sulfide and carbon dioxide; dehydrating thecompressed thermally cracked mixed product stream with a reduced contentof hydrogen sulfide and carbon dioxide; recovering hydrogen from thedehydrated compressed thermally cracked mixed product stream with areduced content of hydrogen sulfide and carbon dioxide; and obtainingolefins and aromatics as in step (f) and pyrolysis fuel oil as in step(g) from the remainder of the dehydrated compressed thermally crackedmixed product stream with a reduced content of hydrogen sulfide andcarbon dioxide; and step (e) comprises purifying recovered hydrogen fromthe dehydrated compressed thermally cracked mixed product stream with areduced content of hydrogen sulfide and carbon dioxide for recycle tothe hydroprocessing zone.
 3. The integrated process of claim 2, whereinrecovering hydrogen from the dehydrated compressed thermally crackedmixed product stream with a reduced content of hydrogen sulfide andcarbon dioxide further comprises separately recovering methane for useas fuel for burners and/or heaters in the thermal cracking step.
 4. Theintegrated process of claim 1 wherein the thermal cracking stepcomprises heating the deasphalted and demetalized oil stream in aconvection section of a steam pyrolysis zone, separating the heateddeasphalted and demetalized oil into a vapor fraction and a liquidfraction, passing the vapor fraction to a pyrolysis section of a steampyrolysis zone, and discharging the liquid fraction.
 5. The integratedprocess of claim 4 wherein the discharged liquid fraction is blendedwith pyrolysis fuel oil recovered in step (g).
 6. The integrated processof claim 4 wherein separating the heated deasphalted and demetalized oilstream into a vapor fraction and a liquid fraction is with avapor-liquid separation device based on physical and mechanicalseparation.
 7. The integrated process of claim 6 wherein thevapor-liquid separation device includes a pre-rotational element havingan entry portion and a transition portion, the entry portion having aninlet for receiving the flowing fluid mixture and a curvilinear conduit,a controlled cyclonic section having an inlet adjoined to thepre-rotational element through convergence of the curvilinear conduitand the cyclonic section, a riser section at an upper end of thecyclonic member through which vapors pass;and a liquidcollector/settling section through which liquid passes.
 8. Theintegrated process of claim 1, further comprising separating thehydroprocessing zone reactor effluents in a high pressure separator torecover a gas portion that is cleaned and recycled to thehydroprocessing zone as an additional source of hydrogen, and liquidportion, and separating the liquid portion from the high pressureseparator in a low pressure separator into a gas portion and a liquidportion, wherein the liquid portion from the low pressure separator isthe hydroprocessed effluent subjected to step (b) and the gas portionfrom the low pressure separator is combined with the mixed productstream after the steam pyrolysis zone and before separation in step (d).9. The integrated process of claim 1, wherein step (b) comprises mixingthe crude oil feedstock with make-up solvent and optionally freshsolvent; transferring the mixture to a primary settler in which aprimary deasphalted and demetalized oil phase and a primary asphaltphase are formed; transferring the primary deasphalted and demetalizedoil phase to a secondary settler in which a secondary deasphalted anddemetalized oil phase and a secondary asphalt phase are formed;recycling the secondary asphalt phase to the primary settler to recoveradditional deasphalted and demetalized oil; conveying the secondarydeasphalted and demetalized oil phase to a deasphalted and demetalizedoil separation zone to obtain a recycle solvent stream and asubstantially solvent-free deasphalted and demetalized oil stream;conveying the primary asphalt phase is conveyed to a separator vesselfor flash separation of an additional recycle solvent stream and abottom asphalt phase, wherein the substantially solvent-free deasphaltedand demetalized oil stream is the feed to the steam pyrolysis zone. 10.The integrated process as in claim 9, wherein the bottom asphalt phaseis blended with pyrolysis fuel oil recovered in step (g).